In drilling a borehole, the borehole can have the same general diameter from the ground surface to total depth (TD). However, most boreholes have an upper section with a relatively large diameter extending from the earth's surface to a first depth point. After the upper section is drilled a tubular steel pipe is located in the upper section. The annulus between the steel pipe and the upper section of the borehole is filled with liquid cement which subsequently sets or hardens in the annulus and supports the liner in place in the borehole.
After the cementing operation is completed, any cement left in the pipe is usually drilled out. The first steel pipe extending from the earth's surface through the upper section is called "surface casing". Thereafter, another section or depth of borehole with a smaller diameter is drilled to the next desired depth and a steel pipe located in the drilled section of borehole. While the steel pipe can extend from the earth's surface to the total depth (TD) of the borehole, it is also common to hang the upper end of a steel pipe by means of a liner hanger in the lower end of the next above steel pipe. The second and additional lengths of pipe in a borehole are sometimes referred to as "liner".
After hanging a liner in a drilled section of borehole, the liner is cemented in the borehole, i.e. the annulus between the liner and the borehole is filled with liquid cement which thereafter hardens to support the liner and provide a fluid seal with respect to the liner and also with respect to the borehole. Liners can be installed in successive drilled depth intervals of a wellbore, each with smaller diameters, and each cemented in place. In any instance where a liner is suspended in a wellbore, there are sections of the casing and of the liner and of adjacent liner sections which are coextensive with another. Figuratively speaking, a wellbore has telescopically arranged tubular members (liners), each cemented in place in the borehole. Between the lower end of an upper liner and the upper end of a lower liner there is an overlapping of the upper and lower liners and cement is located in the overlap sections.
After the liners have been located through the strata of interest, the well if completed. In the completion of a well using a compression type packer, typically a production tubing with a compression type production packer is lowered into the wellbore and disposed or located in a liner just above the formations containing hydrocarbons. The production packer has an elastomer packer element which is axially compressed to expand radially and seal off the cross-section of the wellbore by virtue of the compressive forces in the packer element. Next, a perforating device is positioned in the liner below the packer at the strata of interest. The perforating device is used to develop perforations through the liner which extend into cemented annulus between the liner and the earth formations. Thereafter, hydrocarbons from the formations are produced into the wellbore through the perforations and through the production tubing to the earth's surface. Typically in the production of hydrocarbons there is a pressure differential across the packer element and heat energy is applied to the packer element. The heat energy comes from downhole temperature conditions of the hydrocarbons which are higher than ground surface temperature conditions.
In summary, packer element of a compresion packer used in the well completion is composed of rubber or an elastomer product which is highly compressed to span the annular gap between the liner and the production tubing and is compressed to exert sufficient contact pressure with the wellbore to provide a fluid tight seal. In time, the downhole temperature and differential pressure across the packer element can cause the packer element to deteriorate and consequently to leak.
In other instances in the life of a production well, gas migration or leakage is a particularly significant problem which can occur when fluids migrate along the cemented overlapped sections of a liner and borehole. Any downhole fluid leak outside the production system is undesirable and requires a remedial operation to prevent the leak from continuing.
Some completions use an inflatable packer in preference to a compressive packer. Some operators also prefer to use an inflatable packer to isolate areas of a wellbore where fluid leaks occur.
An inflatable packer typically includes an annular elastomer element (up to about 40 feet in length) on a central steel tubular member which extends therethrough. In use, the inflatable packer is disposed in a borehole on a string of production pipe and is located at the desired location in a borehole. The packer element is adapted to receive a cement slurry or a liquid ("mud") under pressure to inflate and to compress the packer element between the inflation liquid and the wellbore. A valving system in the packer is used to access the cement slurry or mud under pressure in the attached string of tubing to the interior of the elastomer packer element. The inflating pressure of the inflating liquid medium must be such that after the inflating pressure as trapped in the packer element, the packer element maintains a positive seal with respect to the borehole wall. A positive seal is a pressure of the packer element which exceed the pressure in the formations in the wellbore. Inflatable packers seal extremely well in open boreholes.
Heretofore, use of an inflatable packer to provide a gas tight seal in a smooth walled liner to bypass fluid leaks has not been reliable because there has been no reliable way to determine what the inflation pressure for the packer should be in order to obtain the desired packer seal in a liner. Too much pressure in an inflatable packer can overstress a liner or burst the inflatable packer element while too little pressure will not provide a proper packer seal. In some instances, even a fully inflated packer element at maximum inflation pressure will not obtain a gas tight seal in a liner.
In another form of well completion, in hard earth formations, inflatable packers on a production string of pipe can be spaced apart by a section of pipe and inflated to straddle a production zone so that a liner is not required. Such a process is described in U.S. Pat. No. 4,440,225 issued Apr. 3, 1984. U.S. Pat. No. 4,440,225 recognizes that a cement inflated packer can leak under pressure because cement shrinkage in the packer, upon curing, can produce a micro-annulus gap which permits fluid migration. The solution in the patent for cement shrinkage is to algebraically sum the radial elastic compression of the mandrel, the radial elastic compression of the packer element and the radial elastic compression of the formation so that this sum exceeds the radial shrinkage of the cement element upon curing by an amount sufficient that the sealing pressure exceeds the formation pore pressure after the cement is set or cured.
In the present state of technology, it has been discovered that the '225 patent method sometimes overstresses the earth formations and can sometimes result in gas leaks. While having great utility, the method lacks preciseness in predetermining the effectiveness of an inflatable packer seal. Also, the method does not deal with completions where the inflation diameter of an inflatable packer used in a borehole extending below a liner is a factor in the operations.
During and after a well completion, some well operations such as acidizing or fracturing develop a downhole temperature effect on the wellbore elements and can cause fluid leakage.
The net effect of a considerable number of wellbore completion and remedial operations is to temporarily change the temperatures along the wellbore from a normal in-situ temperature condition along the wellbore. At any given level in a wellbore, the temperature change may be an increase or decrease of the temperature condition relative to the normal in-situ temperature depending upon the operations conducted.
What happens then is that an inflatable well packer, which includes metal elastomer and an inflation liquid is normally set in a stressed condition in a metal liner or overlapped sections of liners, which are at a different temperature condition than the normal in-situ temperature conditions. After the operations are concluded and the wellbore returns to its normal in-situ temperature, this change in temperature changes the dimensions of the well packer which affects the stressed condition of the packer. In the case of a cement filled packer, the decrease in volume when the cement cures also affects the stressed condition. These changes in temperature and cement volume can reduce the stressed condition of the packer to a failure mode where the packer leaks after the temperature returns to an in-situ temperature condition.